In the early years of oil drilling and production, wells were primarily drilled on land, to moderate depths, and with relatively minor horizontal offsets. An empirical understanding of the impact of geological forces and earth material properties on required drilling and development practice was developed region by region. Successful practices were defined by trial and (sometimes costly and spectacular) error. It was only once local conditions were understood that it became possible to drill and complete new wells with a sufficient degree of confidence to guarantee the safety and economic success of further field developments. However, techniques that were successful in one field were not necessarily successful in other fields, and therefore the trial and error learning process often had to be repeated.
As wells have become more expensive and complex, both in terms of well geometry (reach and length) and access to deep, high temperature, high pore pressure, and high stress regimes, it has become clear that the economic success of field developments can only be assured if geology and tectonics are understood and field activities are designed with that understanding. Furthermore, constraints on engineering practice based on environmental and societal requirements necessitate specially designed mud formulations and drilling techniques. Development and application of these solutions depends critically not only on an understanding of the processes that act within the earth, but also of the impact of these processes on drilling and completion practice. The study of these processes, and of the interactions between them and their effect on earth materials, is called geomechanics.
Those of ordinary skill in the art will understand that forces in the earth are quantified by means of a stress tensor, in which the individual components are tractions (with dimensions of force per unit area) acting perpendicular or parallel to three planes that are in turn orthogonal to each other. The normals to the three orthogonal planes define a Cartesian coordinate system (x1, x2, x3). FIGS. 1A, 1B, and 1C together illustrate (FIG. 1A) definitions of the stress tensor in Cartesian coordinates; (FIG. 1B) tensor transformation through direction cosines; and (FIG. 1C) the principal stress axes.
The stress tensor has nine components, each of which has an orientation and a magnitude, as shown in FIG. 1A. Three of these components are normal stresses, in which the force is applied perpendicular to the plane (S11 is the stress component acting normal to a plane perpendicular to the x1-axis); the other six are shear stresses, in which the force is applied along the plane in a particular direction (e.g., S12 is the force acting in the x2-direction along a plane perpendicular to the x1-axis). In all cases, Sij=Sji, which reduces the number of independent stress components to six.
At each point there exists a particular stress axis orientation for which all shear stress components are zero, whose directions are referred to as the principal stress directions. The magnitudes of the three principal stresses acting in these directions are S1, S2, and S3, corresponding to the greatest principal stress, the intermediate principal stress, and the least principal stress, respectively. Coordinate transformations between the principal stress tensor and any other arbitrarily oriented stress tensor are accomplished through tensor rotations. It has been found in most parts of the world that, at depths within reach of the drill bit, the stress acting vertically on a horizontal plane (defined as the vertical stress, Sv) is a principal stress. This requires that the other two principal stresses lie in a horizontal plane. Because these horizontal stresses almost always have different magnitudes, they are referred to as the greatest horizontal stress, SHmax and the least horizontal stress, SHmin.
There are a number of different sources of stress in the Earth. Plate tectonic driving forces have constant orientations over wide areas. They are caused by a variety of effects, including ridge push from mid-ocean ridges, slab pull where plates are being subducted, collision resistance forces at converging plate margins such as in Trinidad or the Himalayas, forces along transform faults where plates are moving laterally past each other such as the San Andreas fault in California, and suction above subduction zones such as the NE of Australia.
Another source of stresses in the Earth is referred to as topographic loads, which can be due to large mountain chains such as the Canadian Rockies or the Himalayas, or from addition or removal of loads due to ice sheets or changes in sea level. In this category are gravitational loads such as those associated with sedimentation within basins, and down-slope extensional loads within active depositional sequences.
Lithostatic buoyancy constitutes another category of stress in the Earth because the lithosphere is lower in density than the underlying asthenosphere, it “floats” on the underlying material, and sediment loading and lateral changes in lithospheric thickness or density cause bending forces to develop. Flexural forces, still another category of stress, are generated due to localized topographic loads and to the forces acting on down-going slabs in subduction zones. Finally, earthquakes (slip on faults), active volcanism, and salt diapirism are all examples of processes that act to change local stresses.
Of each of the foregoing categories of stress, the processes that contribute to the in situ stress field primarily include plate tectonic driving forces and gravitational loading. Plate tectonic driving forces cause the motions of the lithospheric plates that form the crust of the earth. Gravitational loading forces include topographic loads and loads due to lateral density contrasts and lithospheric buoyancy. These are modified by the locally acting effects of processes such as volcanism, earthquakes (fault slip), and salt diapirism. Human activities, such as mining and fluid extraction or injection, can also cause local stress changes.
Because the largest components of the stress field (gravitational loading and plate driving stresses) act over large areas, stress orientations and magnitudes in the crust are remarkably uniform. However, local perturbations, both natural and man-made, are important to consider for application of geomechanical analyses to drilling and reservoir engineering. There are countless real-world examples of regions wherein the individual stress orientations within fields in the region are quite uniform, the stress varies systematically among the individual fields. It is also well known to those of ordinary skill in the art that stresses can be different within different geological layers, or within different fault blocks within the earth, and that adjacent to local sources of stress perturbation the stresses can change with position on a foot-by-foot basis.
Vertical stress can be the greatest, the intermediate, or the least principal stress. A classification scheme has been used to describe these three possibilities based on the type of faulting that would occur in each case. Table 1 sets forth definitions of the greatest principal stress (S1) and the least principal stress (S3) for different fault classifications.
TABLE 1FAULT REGIMES1S3NormalSVSHminStrike-slipSHmaxSHminReverseSHmaxSV
A normal faulting regime is one in which the vertical stress is the greatest stress. When the vertical stress is the intermediate stress, a strike-slip regime is indicated. If the vertical stress is the least stress, the regime is defined to be reverse. The horizontal stresses at a given depth will be smallest in a normal faulting regime, larger in a strike-slip regime, and greatest in a reverse faulting regime. In general, vertical wells are found to be progressively less stable as the regime changes from normal to strike-slip to reverse, and consequently require higher mud weights to drill.
Those of ordinary skill in the art will appreciate the desirability in many instances of drilling wellbores in particular orientations relative to the in situ stresses present along the wellbore trajectory. In particular, positioning a well in a specific orientation with respect to the in situ stress field or in a specific geological horizon selected on the basis of the state of stress can significantly improve or degrade the performance of the completed well. In the latter case, it is well known that placing a well within a geological horizon with a lower stress can improve the efficiency of hydraulic fracturing as well as its effectiveness for production or injection. This is in part because when the stress magnitude is smaller it requires a lower pressure to induce a fracture by fluid injection, and also in part because when the stress magnitude is smaller it is easier to maintain the desired fracture aperture and flow properties over the life of the well.
It is also well known that the orientation of a well with respect to the stresses can also improve or degrade the efficiency with which a well can be completed using other techniques such as by means of first casing and then perforating the casing in the well to connect the well to the fluid-bearing formation. The orientation of the well with respect to the stresses can also affect the cost of the installed hardware necessary to achieve well objectives. Such objectives are discussed in further detail in U.S. Pat. No. 7,181,380 to Dusterhoft et al., having the same assignee as the present disclosure and the contents of which are incorporated herein by reference. As disclosed in Dusterhoft, obtained information regarding pore pressure depletion, stress magnitudes and orientations, and strength of rock formation from hydrocarbon recovery modeling is used to determine optimum well completion design including the selection of a completion type, trajectory, and location. Additionally, the process may also consider probable failure mechanisms and identified completion requirements, and their corresponding effect on completion options.
One example of the benefit of optimally orienting a well trajectory with respect to the in situ stress field is in the case of a naturally fractured reservoir, where the flow properties of the natural fractures (which may have random or multiple orientations) depend on their orientation with respect to the principal stresses. In many cases the most permeable fractures in the earth are the subset of fractures that are optimally oriented for slip under the current stress field. In any case, the orientations of the natural fractures most likely to be permeable (the optimally oriented fractures) can be determined if the stress orientations and magnitudes are known. Because wells drilled perpendicular to the optimally oriented fractures will intersect the greatest number of these fractures and thus will have the highest likelihood of maximizing fluid flow connectivity to those fractures, it is possible simply by knowing the magnitudes and orientations of the stresses to select the best well orientation to maximize fluid flow between the well and the natural fractures in the earth.
In many cases, maximizing productivity or injectivity requires maximizing connections to natural fractures. In other cases, it is preferred to minimize connections to permeable fractures. Wells that achieve this latter objective have orientations that can also be computed using known techniques, but only if the stress magnitudes and orientations are known. Since stresses vary locally, it is advantageous in either case to have a method to determine the stresses and their orientations while the well is being drilled and to have the ability to change the well orientation if the stresses change. Knowing the stresses and their orientations then allows identifying in the current well on a foot-by-foot basis the degree of connection of the well to naturally permeable fractures, which in turn allows in either case selection of the best locations for perforations in cased and perforated wells.
Another example of the benefit of optimally orienting a well is in the case of a well that is to be completed by stimulation using hydraulic fracturing. Hydraulic fractures are known to propagate in most earth materials in directions such that they are perpendicular to the least principal stress. Therefore, wells that are drilled parallel to the least principal stress (SHmin), when stimulated using hydraulic fracturing, will have fractures that are perpendicular to the well axis. In a cased and perforated well, selectively perforating at discrete intervals and selectively stimulating each interval separately will result in a series of parallel fractures extending radially away from the well. This is optimal in certain circumstances to efficiently achieve maximum production from a field (or, in the case of so-called disposal wells, to achieve maximum injectivity for fluid disposal). In other cases, it is desirable to drill a well such that a single fracture is created by hydraulically stimulating the well that lies along the well axis. In this case, it is desirable to drill the well parallel to the intermediate or to the greatest principal stress. Wells drilled in orientations that deviate only a small amount from these optimal orientations will be much more difficult to stimulate, and will have geometries of the induced fractures that are significantly different from the desired geometries. Because stresses can vary locally, it is desirable to know on a localized basis (e.g., foot-by-foot) the local orientation of the stress field, so that fracture stimulations can be selectively carried out only where the well has the best orientation with respect to the local in situ stress field to achieve the desired result.
Although these and other advantages to optimally orienting wellbores relative to stress fields are known to persons of ordinary skill in the art, there remains an unmet demand for improvement in the manner by which wellbores can be so optimally oriented.